International exploration & production

Management’s Discussion & Analysis

Three and Nine Months Ended December 31, 2009 and 2008

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MANAGEMENT’S DISCUSSION AND ANALYSIS – February 11, 2010

The following Management’s Discussion and Analysis (MD&A) as provided by the management of Bengal Energy Ltd.

(“Bengal” or the “Company”) should be read in conjunction with the unaudited interim Consolidated Financial

Statements and notes thereto for the three and nine months ended December 31, 2009 and 2008 and the audited

Consolidated Financial Statements, related notes and MD&A for the years ended March 31, 2009 and 2008. The reader

should be aware that historical results are not necessarily indicative of future performance.

The Company’s activities are focused in Australia, India and Canada. Over the reporting period, revenue and expenses

were generated and capital expenditures were made in Australia and Canada, and capital expenditures were made in

India. The Company’s activities are carried out primarily in Canadian dollars as well as the currencies of each country in

which the Company operates. The Company reports financial results in Canadian dollars.

Basis of Presentation - The financial statements and financial data presented herein were prepared in accordance

with Canadian generally accepted accounting principles (GAAP). The reporting and the functional currency is the

Canadian dollar. For the purpose of calculating unit costs, natural gas volumes have been converted to barrels of oil

equivalent (boe) using a conversion ratio of six thousand cubic feet (mcf) of natural gas to one barrel (bbl) of oil. The

following MD&A compares the results of the nine months ended December 31, 2009 (“YTD 2010”) to the nine months

ended December 31, 2008 (“YTD 2009”) and the results of the three months ended December 31, 2009 (“Q3 2010”) to

the three months ended December 31, 2008 (“Q3 2009”) and the results of the three months ended September 30,

2009 (“Q2 2010”).

Non-GAAP Measurements – Within the MD&A references are made to terms commonly used in the oil and gas

industry. Funds from operations, funds from operations per share and netbacks are not defined by GAAP in Canada

and are referred to as non-GAAP measures. Funds from operations per share is calculated based on the weighted

average number of common shares outstanding consistent with the calculation of net income per share. Netbacks equal

total revenue less royalties and operating and transportation expenses calculated on a boe basis. Management utilizes

these measures to analyze operating performance. Funds from operations is not intended to represent operating profit

for the period nor should it be viewed as an alternative to operating profit, net income, cash flow from operations or

other measures of financial performance calculated in accordance with Canadian GAAP. Funds from operations is

commonly referred to as cash flow by research analysts, is used to value and compare oil and gas companies and is

frequently included in published research when providing investment recommendations. Total boes are calculated by

multiplying the daily production by the number of days in the period.

The following table reconciles cash flow from operations to funds from operations, which is used in the MD&A:

Three Months Ended Nine Months Ended

$000s 12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

Cash flow from (used in) operations (264) 303 (263) (1,157) 1,858Abandonment expenditures - - - 21 12Changes in non-cash working capital (83) (332) (32) 196 (673)

Funds from (used in) operations (347) (29) (295) (940) 1,197

Forward-looking Statements - Certain statements contained within the Management’s Discussion and Analysis, and

in certain documents incorporated by reference into this document, constitute forward-looking statements. These

statements relate to future events or Bengal’s future performance. All statements other than statements of historical fact

may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of

words such as "seek,” "anticipate,” "budget,” "plan,” "continue,” "estimate,” "expect,” "forecast,” "may,” "will,” "project,”

"predict,” "potential,” "targeting,” "intend,” "could,” "might,” "should,” "believe" and similar expressions. These statements

involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ

materially from those anticipated in such forward-looking statements. Bengal believes the expectations reflected in

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those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to

be correct and such forward-looking statements included in, or incorporated by reference into, this MD&A should not be

unduly relied upon.

In particular, this Management’s Discussion and Analysis, and the documents incorporated by reference, contain

forward-looking statements pertaining to the following:

Oil and natural gas production levels;

The size of the oil and natural gas reserves;

Projections of market prices and costs;

Expectations regarding the ability to raise capital and to continually add to reserves through acquisitions

and development;

Treatment under governmental regulatory regimes and tax laws;

Capital expenditures programs and estimates of costs;

Expectations that Bengal’s future realized gas and oil prices will coincide with the B.C Station 2 and TAPIS

daily index prices;

Funding of working capital requirements, commitments and other planned expenses will be by cash on hand,

farm-outs, joint ventures or share issues;

Sufficiency of funds to meet working capital requirements, commitments and planned expenditures;

Commencement of exploration and development activities on Blocks CY-ONN-2005/1 and CY-OSN-2009/1 in

India;

Commencement of exploration and development activities on Permit AC/P 47 offshore Australia;

Closing of acquisition of ATP 752P in Australia;

Completion of PEL 103A core hole program in Australia;

Extension of license on AC/P24;

Estimates of start up and production levels for the Cuisinier well in Australia;

Suggested pay sands and production start date of the Cuisinier well; and,

Future amount and timing of activity to be carried out by the Santos Joint Venture.

With respect to the forward looking statements contained in the MD&A, Bengal has made assumptions regarding: future

commodity prices; the impact of royalty regimes; the timing and the amount of capital expenditures; production of new

and existing wells and the timing of new wells coming on stream; future operating expenses including processing and

gathering fees; the performance characteristics of oil and natural gas properties; the size of oil and natural gas

reserves; the ability to raise capital; the continued availability of undeveloped land and skilled personnel; the ability to

obtain equipment in a timely manner to carry out exploration and development activities; the ability to obtain financing

on acceptable terms; the ability to add production and reserves through exploration and development activities; and the

continued stability of political, regulatory; tax and fiscal regimes in which the Company has operations.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the

risk factors set forth below and elsewhere in this Management’s Discussion and Analysis:

Volatility in market prices for oil and natural gas;

Liabilities inherent in oil and natural gas operations;

Uncertainties associated with estimating oil and natural gas reserves;

Competition for, among other things: capital, acquisitions of reserves, undeveloped lands and

skilled personnel;

Incorrect assessment of the value of acquisitions;

Unable to meet commitments due to inability to raise funds or complete farm-outs;

Geological, technical, drilling and processing problems;

Changes in income tax laws or changes to royalty and environmental regulations relating to the oil and gas

industry; and,

Counter-party credit risk, stock market volatility and market valuation of Bengal’s stock.

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Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the

implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be

profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The

forward-looking statements contained in this MD&A and the documents incorporated by reference herein are expressly

qualified by this cautionary statement. The forward-looking statements contained in this document speak only as of the

date of this document and Bengal does not assume any obligation to publicly update or revise them to reflect new

events or circumstances, except as may be required pursuant to applicable securities laws.

Additional information can also be found in Bengal’s Annual Information Form dated June 22, 2009, available on

SEDAR at www.sedar.com.

HIGHLIGHTS

$000s except per share, volumes and netback amounts

Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

RevenueNatural gas $ 186 $ 516 $ 218 $ 623 $ 1,753Natural gas liquids 19 67 67 142 411Oil 208 242 220 727 2,095

Total 413 825 505 1,492 4,259Royalties 53 125 74 192 739

% of revenue 12.7 15.2 14.8 12.8 17.4Operating & transportation 164 211 230 640 862Netback

(1) 196 489 201 660 2,658

Cash flow from (used in) operations: (264) 303 (263) (1,157) 1,858Per share ($) (basic & diluted) (0.01) 0.02 (0.01) (0.06) 0.10

Funds from (used in) operations:(2) (347) (29) (295) (940) 1,197

Per share ($) (basic & diluted) (0.02) (0.00) (0.02) (0.05) 0.07

Net (loss): (885) (6,196) (1,848) (3,598) (7,359)Per share ($) (basic & diluted) (0.05) (0.34) (0.10) (0.20) (0.40)

Capital expenditures $ 1,120 $ 1,096 $ (426) $ 848 $ 6,470

Property disposition proceeds $ - $ - $ 2,111 $ 2,111 $ -

VolumesNatural gas (mcf/d) 422 842 787 631 729Natural gas liquids (boe/d) 6 19 17 13 19Oil (bbl/d) 24 46 36 34 63Total (boe/d @ 6:1) 100 205 184 152 203

Netback(1)

($/boe)Revenue $ 44.89 $ 43.69 $ 29.70 $ 35.60 $ 76.22Royalties 5.69 6.63 4.39 4.57 13.23Operating & transportation 17.81 11.16 13.54 15.27 15.43

Total $ 21.39 $ 25.90 $ 11.77 $ 15.76 $ 47.56

(1) Netback is a non-GAAP measure. Netback per boe is calculated by dividing the revenue and costs in total for the

company by the total production of the company measured in boe.

(2)Funds from operations is a non-GAAP measure. The comparable GAAP measure is cash flow from operations. A

reconciliation of the two measures can be found in the table on page 1.

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RESULTS OF OPERATIONS

Production

The following table outlines Bengal’s production volumes for the periods indicated:

Production Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

Natural Gas (mcf/d) 422 842 787 631 729

NGLs (boe/d) 6 19 17 13 19

Oil (bbls/d) 24 46 36 34 63

Total (boe/d) 100 205 184 152 203

Gas production volumes declined in the current quarter compared to the previous quarters mainly due to the sale of four

Kaybob gas wells on September 24, 2009. Oil volumes produced from the Company’s Toparoa well in the Cooper Basin

of Australia decreased as the well was shut in nine days to repair an engine and due to natural reservoir decline.

The Company expects natural decline from the Toparoa well will continue but anticipates overall oil production to

increase upon commencement of production from the Cuisinier well in the first quarter of 2010.

YTD 2010 production declined 51 boe\d or 25% compared to YTD 2009 due to natural reservoir decline of the Toparoa

oil well and sale of the Kaybob property.

Pricing

Oak, British Columbia gas sales are marketed by the operator and the price received is based on the reference price at

British Columbia’s Station 2 plus $0.03 per mcf.

NGLs include condensate, pentane, butane and propane. While prices for condensate and pentane have a relatively

strong correlation to oil prices, prices for butane and propane trade at varying discounts due to the market conditions of

local supply and demand. Bengal had two NGL marketing contracts which expire March 31, 2010. Both contracts were

assigned to the purchaser on close of the sale of the Kaybob property in September 2009.

Bengal’s realized price for its Australian oil production is based on the Tapis Crude benchmark price plus a small quality

premium. Tapis is the main regional reference price for light sweet crude oils in South East Asia and is used as the

reference price for Australian oil producers. Tapis has been trading at an average premium to West Texas Intermediate

(WTI) of US $3.46 per bbl over the past year. Bengal’s realized oil price is significantly higher than Tapis in the current

quarter as actual sales prices received in the quarter were much higher than prices used to accrue sales at September

30, 2009.

The following table outlines benchmark prices compared to Bengal’s realized prices:

Prices and Marketing Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

Average Benchmark Prices

AECO 30 day firm ($/mcf) $ 4.23 $ 6.78 $ 3.03 $ 3.64 $ 8.46

TAPIS oil ($US/bbl) 77.15 60.73 71.69 71.51 104.61

Cdn/Aus exchange rate 0.96 0.80 0.91 0.92 0.90

WTI oil ($US/bbl) $ 76.16 $ 58.71 $ 68.29 $ 68.05 $ 100.19

Bengal’s Realized Price ($ CAD)

Natural gas ($/mcf) $ 4.80 $ 6.66 $ 3.01 $ 3.59 $ 8.75

Oil ($/bbl) 96.58 56.71 65.53 76.92 121.13

NGLs ($/bbl) 31.74 39.30 42.72 39.94 79.24

Total ($/boe) $ 44.89 $ 43.69 $ 29.70 $ 35.60 $ 76.22

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Petroleum and Natural Gas Sales

The following table outlines Bengal’s production sales by category for the periods indicated below:

Petroleum and

Natural Gas

Sales ($000s)

Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

Natural gas $ 186 $ 516 $ 218 $ 623 $ 1,753

NGLs 19 67 67 142 411

Oil 208 242 220 727 2,095

Total $ 413 $ 825 $ 505 $ 1,492 $ 4,259

Revenue declined in the current quarter by 18% or $92,000 from the prior quarter ended September 30, 2009. The

decline was mainly due to lower gas volumes due to the sale of the Kaybob property in September, 2009 partially offset

by higher commodity prices. Revenues for the quarter ended December 31, 2009 decreased by 50% or $412,000 from

the prior year comparable period due to a sale of Kaybob, lower gas prices and natural decline in Toparoa oil

production.

YTD 2010 revenue declined 65% or $2,767,000 from YTD 2009 due to 53% lower commodity prices, the sale of the

Kaybob property and lower oil production.

Royalties

Royalty payments are made by oil and natural gas producers to the owners of the mineral rights on the leases. These

owners include governments (Crown) and freehold landowners as well as other third parties that may receive

contractual overriding royalties.

In Alberta, royalties on natural gas and NGLs are charged by the government based on an established monthly

reference price. Bengal also paid a 7.5% gross overriding royalty (GORR) on two of the Kaybob gas wells which were

sold on September 24, 2009.

In British Columbia, royalties are calculated based on average daily production from a well multiplied by a reference

price. Bengal also pays a GORR to the landholder of between 7.5% and 10% on its Oak gas wells.

Royalties by Type ($000s)

Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/2009 12/31/2008

Canada Crown $ 23 $ 86 $ 40 $ 81 $ 412Canada gross overriding 12 15 12 43 140Australian Government 18 24 22 68 187

Total $ 53 $ 125 $ 74 $ 192 $ 739

$/boe 5.69 6.63 4.39 4.57 13.23% of revenue 12.7 15.2 14.8 12.8 17.4

Royalties by Commodity

Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

Natural gas$000s $ 30 $ 81 $ 46 $ 93 $ 431$/mcf 0.77 1.05 0.64 0.53 2.15% of revenue 16.1 15.7 21.4 14.8 24.6

Oil$000s $ 18 $ 24 $ 22 $ 68 $ 187$/bbl 8.23 6.68 6.59 7.21 10.84% of revenue 8.5 10.0 10.1 9.4 8.9

NGLs$000s $ 5 $ 20 $ 6 $ 31 $ 121$/bbl 8.07 11.58 3.77 8.77 23.30% of revenue 25.4 29.5 8.8 21.9 29.4

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The decrease in Bengal’s royalties for the three months ended December 31, 2009 to $53,000 compared with $127,000

in the same period of the previous year is due to lower production volumes and gas prices in the current period.

In Australia, oil royalties are based on a Government established rate of 11%. The royalty rate is applied to gross

revenues after deducting an allowance for transportation and operating costs resulting in an effective rate of less

than 11%.

YTD 2010 royalties declined $547,000 or 74% from the prior year comparable period due to a 53% decline in

commodity prices and 25% lower production volumes.

Operating & Transportation Expenses

Operating and transportation costs for the three months ended December 31, 2009 were reduced $47,000 from the

prior comparable period but increased on a boe basis by 60% from $11.16 to $17.81 per boe. Overall costs decreased

due to sale of the Kaybob property and lower transportation costs due to less oil production being transported. Costs

per boe increased as some of the operating costs are fixed and with declining volumes, costs per boe increase and due

to a 13th

month adjustment charged in the current quarter by a partner on a non-operated property..

Costs in the nine months ended December 31, 2009 were reduced $0.81 per boe or $249,000 from the nine months

ended December 31, 2008 due to the sale of the Kaybob property, lower transportation costs on declining oil volumes

and the prior period included workover costs for the Company’s Oak property.

Transportation costs in Australia are incurred to get Bengal’s oil production from the wellhead to the Limestone Creek

processing facility. From there the oil is pipelined to the Moomba facility which accepts production from 115 gas fields

and 28 oil fields through approximately 5,600 kilometers of pipelines. The oil is then sent through a pipeline to Port

Bonython, South Australia.

Operating Expenses ($000s) Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

Australia

Operating $ 14 $ 12 $ 20 $ 51 $ 58

Transportation 33 51 48 135 225

47 63 68 186 283

Canada – Operating costs 117 148 162 454 579

Total $ 164 $ 211 $ 230 $ 640 $ 862

Australia

Operating - $/boe 6.65 2.90 6.13 5.45 3.36

Transportation - $/boe 14.99 12.01 14.32 14.26 13.00

Canada - $/boe 16.64 10.07 11.85 13.98 15.02

Total ($boe) $ 17.81 $ 11.16 $ 13.54 $ 15.27 $ 15.43

General and Administration (G&A) Expenses

YTD 2010 G&A costs decreased $151,000 or 9% compared to YTD 2009 due to lower rent and salaries resulting from

closure of Bengal’s Australian office in the prior period. On a boe basis YTD G&A costs increased 22% as lower

expenses were more than offset by lower volumes.

G&A costs were $30,000 or 5% lower in the quarter ended December 31, 2009 compared to the comparable prior

period due to closure of the Australian office. Costs per boe increased from the prior quarter and prior year quarter due

to lower production volumes.

General and Administrative Expenses

Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

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($000s)

G&A $ 540 $ 570 $ 527 $ 1,590 $ 1,741

G&A ($/boe) $ 58.62 $ 30.21 $ 30.99 $ 37.93 $ 31.17

Stock-based compensation

The Company applies the fair value method for valuing stock option grants. Under this method, compensation costs

attributable to all share options granted are measured at fair value at the grant date and expensed over the vesting

period with a corresponding increase to contributed surplus.

In December 2009, 612,000 stock options were granted to employees and directors. The options expire three years

from the grant date; they vest one-third on the grant date and one-third on each of the following two annual

anniversaries, and have an exercise price of $1.26 per option which was the market price of the Company’s shares at

the time of the grant. The fair value of the options is $320,000 using the Black-Scholes option pricing model.

In March 2009, 685,000 stock options were granted to employees and directors. The options expire five years from the

grant date; they vest one-third on the grant date and one-third on each of the following two annual anniversaries, and

have an exercise price of $0.36 per option which was the market price of the Company’s shares at the time of the grant.

The fair value of the options is $129,000 using the Black-Scholes option pricing model.

For the three months ended December 31, 2009 stock-based compensation expense is $114,000 compared to $5,000

in the prior comparable period. The higher expense is due to the grant of 612,000 options in December 2009 with an

estimated fair value of $320,000; one-third of which is included in compensation expense in the current quarter. In the

prior comparable quarter the expense was reduced by $49,000 due to the forfeiture of 161,000 stock options in October

2008, of which 37,332 had not vested.

In the current quarter 402,700 options expired and 10,000 were forfeited which had not vested. The forfeited options

reduced stock based compensation by $9,000. At December 31, 2009 there is $267,000 of stock-based compensation

remaining to be amortized over the next two years.

The Company recorded stock-based compensation expense related to warrants of $54,000 (2008 - $48,000) for the

three months ended December 31, 2009. At December 31, 2009 there is $268,000 of fair value related to the warrants

to be amortized.

Depletion, Depreciation and Accretion (DD&A)

DD&A Expenses ($000’s) Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

DD&A – Australia $ 176 $ 1,004 $ 75 $ 490 $ 2,549

DD&A – Canada 194 220 369 883 794

Subtotal 370 1,224 444 1,373 3,343

Australia – Ceiling test write down - 3,133 - - 3,133

Total $ 370 $ 4,357 $ 444 $ 1,373 $ 6,476

$/boe – Australia 81.18 235.82 22.57 51.76 147.33

$/boe – Canada 27.66 15.03 27.07 27.22 20.58

$/boe – Sub-total 40.21 64.79 26.18 32.75 59.83

$/boe – Australia (Ceiling test) - 166.05 - - 56.09

$/boe – Total $ 40.21 $ 230.84 $ 26.18 $ 32.75 $ 115.92

Prior to the effect of the December 31, 2008 ceiling test impairment charge, depletion, depreciation and accretion

(“DD&A”) in the three months ended December 31, 2009 declined $854,000 or $24.58 per boe to $370,000 from

$1,224,000 in the prior year comparable quarter. The lower Australian expense and DD&A rate in the current quarter is

due to a reduction in Australian depletable costs resulting from the $3,133,000 ceiling test impairment charge recorded

on December 31, 2008. DD&A expense in Canada declined due to lower production volumes but increased on a boe

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basis due to lower reserve estimates in the current YTD period. Australian DD&A expense per boe increased from Q2-

2010 to Q3-2010 due to the addition of capital costs to the depletable cost pool with no corresponding addition to

reserves.

YTD 2010 DD&A decreased $1,970,000 or 59% compared to YTD 2009 excluding the prior year impairment charge due

to lower production volumes and DD&A rates in the current YTD period. DD&A per boe declined in Australia and

increased in Canada for the reasons explained above.

Bengal has excluded $3.7 million (Q3-2009 - $3.0 million) from the depletion base related to unproved properties in Q3-

2010 and included $50,000 (Q3-2009 - $322,000) in future development costs related to proved reserves.

In the current period Bengal performed a ceiling test calculation of both its Australian and Canadian cost centres and no

impairment charge was required.

Funds from (used in) Operations and Net Loss

Q3-2010 funds used in operations totaled ($347,000) or ($0.02) per basic and diluted share. Funds used in operations

for Q2-2010 was ($295,000) or ($0.02) per basic and diluted share. Funds used in operations for Q3-2009 was

($29,000) or ($0.00) per basic and diluted share. Funds used in operations in Q3-2010 decreased from Q3-2009

primarily due to lower production volumes. YTD 2010 funds used in operations was ($940,000) or ($0.05) per basic and

diluted share compared to funds from operations of $1,197,000 or $0.07 per basic and diluted share for YTD 2009.

YTD funds from operations declined over the prior year comparable period due to lower commodity prices and sale of

the Kaybob property on September 24, 2009. The change in non-cash working capital and abandonment expenditures

are removed from the GAAP measure cash flow from (used in) operations to arrive at the non-GAAP measure funds

from (used in) operations.

The Q3-2010 net loss was $885,000 compared to losses of $1,848,000 in Q2-2010 and $6,196,000 in Q3-2009. On a

per share basis, the net loss in Q3-2010 was $0.05 per basic and diluted share compared to Q2-2010 loss of $0.10 per

basic and diluted share and Q3-2009 loss of $0.34 per basic and diluted share. The YTD 2010 loss is $3,598,000 or

$0.20 per basic and diluted share compared to a loss of $7,359,000 or $0.40 per basic and diluted share for YTD 2009.

CAPITAL EXPENDITURES

Geological and geophysical expenses totalled $934,000 YTD 2010 and $614,000 in Q3-2010 and relate to seismic

acquisition, interpretation and analysis on all of the Company’s lands including prospect identification and play

development. Also included in Geological and geophysical costs are costs related to acquiring Block CY-OSN-2009/2

under the NELP VIII bid round in India. Current quarter drilling costs are for the first well in a two well program on the

Company’s PEL 103A Block in Australia to evaluate the Coal Seam Gas potential of the Innamincka Dome. The credit

in drilling costs YTD is due to the final cost of a well drilled in the prior year being less than originally estimated. As a

result an accrual for the estimated costs of $594,000 related to the well was reversed. Completion costs were incurred

in the current quarter to complete and install artificial lift on the Company’s Cuisinier well in the Cooper Basin of

Australia.

On September 24, 2009 the Company disposed of its interest in the Kaybob property for net proceeds of $2,111,000.

The disposition resulted in a $3,117,000 reduction to petroleum and natural gas assets, the removal of $63,000 of asset

retirement obligations and a loss of $943,000.

Capital Expenditures ($000s) Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 012/31/08

Geological and geophysical $ 614 $ 368 $ 168 $ 934 $ 846Drilling 224 428 (594) (370) 5,207Completions 282 169 - 284 196

Total oil and gas additions 1,120 965 (426) 848 6,249

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Office - 131 - - 221

Total expenditures $ 1,120 $ 1,096 $ (426) $ 848 $ 6,470Property disposition - - (2,111) (2,111) -

Total net expenditures $ 1,120 $ 1,096 $ (2,537) $ (1,263) $ 6,470

SHARE CAPITAL

The Company has an unlimited number of common shares authorized for issuance. On February 11, 2010 there were

18,212,783 common shares issued and outstanding on a post consolidation basis.

On July 17, 2008 Avery Resources Inc. consolidated its shares on a 5:1 basis and renamed the company Bengal

Energy Ltd.

At February 11, 2010, there are 1,764,666 employee stock options outstanding with a weighted average exercise price

of $1.37 per share – of these, 900,009 have vested and are exercisable at an average price of $1.93 per share. These

options expire between 2010 and 2014 with a weighted average remaining life of 3.1 years.

Trading History Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

High $ 1.97 $ 1.00 $ 0.61 $ 1.97 $ 2.90Low 0.49 0.17 0.30 0.27 0.17Close $ 1.58 $ 0.32 $ 0.49 $ 1.58 $ 0.32Volume (000s) 1,301 915 374 2,494 3,220

The above figures are presented on a post-consolidated basis. On November 1, 2007, trading in Avery Resources Inc.

(Bengal’s predecessor company) moved from the TSX Venture Exchange to the TSX. On July 21, 2008 Bengal Energy

Ltd. began trading on the TSX under the symbol BNG.

Share Information (000s)(prior periods adjusted for 5:1 consolidation)

Three Months Ended Nine Months Ended

12/31/09 12/31/08 09/30/09 12/31/09 12/31/08

Shares outstandingBasic and diluted 18,213 18,213 18,213 18,213 18,213

Weighted average shares outstandingBasic and diluted 18,213 18,213 18,213 18,213 18,212

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2009 the Company had working capital of $2,501,000, including cash and short term deposits of

$2,853,000, compared to working capital of $3,970,000 and cash and short term deposits of $3,740,000 at September

30, 2009. The Company’s future capital expenditure plans are discussed below in the ‘Commitments” section and the

“Outlook” section. The Company invests surplus cash only in guaranteed investment certificates.

As the Company does not currently generate sufficient cash flow from operating activities to fund its operating activities

and work commitments, it will consider raising equity financing and / or entering into farm-out arrangements to finance

its exploration activities as appropriate.

Contractual Arrangements

The Company is committed to minimum annual operating lease payments on its premises in Canada in the amount of

$31,000 for the balance of the year ended March 31, 2010 and $42,000 from April to July, 2010.

The Company also has asset retirement obligations with respect to the abandonment and reclamation of wells and

facilities owned by the Company. Bengal includes the present value of the estimated liabilities for such costs on its

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balance sheet. The total estimated undiscounted cost of these liabilities at December 31, 2009 was $161,000

(2008 - $310,000).

Contractual Obligations ($000s) TotalLess than

1 Year

1-3

Years

4-5

Years

After

5 Years

Office lease $ 73 $ 73 $ - $ - $ -

Asset retirement obligations 161 28 34 20 79

Total Contractual Obligations $ 234 $ 101 $ 34 $ 20 $ 79

Bengal has the following work commitments:

Exploration Block AC/P47 – Offshore Australia

Year of Term of

Permit

Permit Year

Starts

Permit Year

Ends

Minimum Work

Requirements

Estimated Expenditure

(AUD$)

1 March 3, 2009 March 2, 2010985km 2D Seismic

Reprocessing$250,000

2 March 3, 2010 March 2, 2011750km sq 3D Seismic

Survey$7,000,000

3 March 3, 2011 March 2, 2012 Geotechnical Studies $1,000,000

4 March 3, 2012 March 2, 2013 Geotechnical Studies $500,000

Bengal is actively looking for parties to enter into joint venture or farm-out arrangements to finance its exploration

commitments under this license.

Purchase & Sale Agreement – Onshore Australia Block ATP 732P

On December 10, 2009 Bengal entered into a Purchase & Sale Agreement and upon satisfaction of all conditions in the

Agreement, Bengal will be required to pay AUD$1,000,000 to acquire 100% interest in ATP 732P.

Bengal’s other licenses and related work commitments are discussed further in the Outlook section below.

RELATED PARTY TRANSACTIONS

There were no related party transactions during the quarter ended December 31, 2009 or in the prior year

comparable period.

OFF BALANCE SHEET TRANSACTIONS

The Company does not have any off balance sheet transactions.

OUTLOOK

Bengal has an extensive inventory of short-term, medium-term and long-term oil and natural gas drilling opportunities in

India and Australia. These opportunities range from the Cuisinier oil discovery in Australia’s Cooper Basin where

production is expected to come on stream shortly to high-impact drilling prospects on 574,000 gross acres in India. The

Company’s total undeveloped land position now exceeds 2.3 million net acres.

INDIA

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Bengal’s potential in India continues to grow. In October 2009, the Company announced that its wholly-owned

subsidiary, Bengal Energy International Inc, was named the provisional winner of block CY-OSN-2009/1 by India’s

Directorate General of Hydrocarbons at the New Exploration Licensing Policy bid round in New Delhi, India. This block

consists of a 100% working interest in 340,000 offshore acres in India’s Cauvery Basin. This was the third significant

exploration block awarded to Bengal in a producing basin since late 2008. The Company expects to sign a production

sharing contract (“PSC”) with the Government of India in the first quarter of 2010, turning the provisional award of block

CY-OSN-2009/1 into a formal agreement, at which time exploration activities will commence.

At CY-OSN-2009/1, Bengal is required to obtain 310 line kilometers of 2D seismic data and 81 square kilometers of 3D

seismic data during the first four years of the seven-year exploration phase. The committed work program capital

expenditure is estimated at US$2,020,000 (about $6/acre). Drilling will be required to hold the block after the first four

years of exploration. A one-time bank guarantee of approximately US$151,500 will be submitted at the time of the

signing of the PSC.

The first exploration block awarded to Bengal over the past 14 months was a 30% working interest in 234,000 onshore

acres in India at CY-ONN-2005/1. Exploration work on the block is expected to begin after Bengal is granted a

Petroleum Exploration License (“PEL”) from the provincial government early in 2010. In the first year of the initial four-

year phase of exploration activities, Bengal and its partners – two oil companies owned by the Indian government –

plan to undertake an aggressive exploration campaign comprising 2,000 km of airborne magnetometry survey, 1,000

km of existing 2D seismic data reprocess and the acquisition of 500 km. sq. of 3D seismic data. Bengal’s net cost for

the first year of exploration activity is expected to be US$2,700,000. A bank guarantee in the amount of US$945,000

will be submitted at the time of granting of the PEL. This bank guarantee is renewed each year based on 35% of the

budget for that year.

AUSTRALIA

Bengal’s third new exploration block is at AC/P 47 in the Timor Sea offshore Australia. The Company has a 100%

working interest in 861,000 acres on the block and is also the operator. Bengal has budgeted $250,000 for early

seismic reprocessing and testing and is collecting all available seismic data records from the associated regulatory

agencies. The Company does not expect to acquire new seismic data until year two of the permit, which ends in

March 2011.

Most recently, Bengal signed an agreement to acquire a 100% working interest in the exploration block ATP 732P. ATP

732P consists of 654,321 gross acres near producing oil and gas fields in Australia’s Cooper Basin. The acquisition is

subject to the grant of an Authority to Prospect (“ATP”) by the government of the state of Queensland in Australia. After

reaching a Native Title Agreement with the Boonthamurra People in September 2009, Bengal is now awaiting approval

from the state government for exploration activities to begin. Anticipated expenditures will be approximately AU$1

million over the year following the ATP grant. This grant is expected by the end of March 2010.

Initial production is expected shortly at the Cuisinier oil discovery in Australia’s Barta block at ATP 752P .Production

facilities have been installed and a production license has been received. Production is expected during the first quarter

of 2010, as soon as marketing and transportation contracts have been executed. Processing of the 103 km sq Cuisinier

3D seismic survey is now complete and a development plan is being crafted for the remainder of 2010.

Also in Australia, Bengal’s joint-venture partner recently received approval from Primary Industries and Resources SA,

an agency of the Government of South Australia, to commence a coal seam test-coring program to evaluate coal seam

methane potential on PEL 103A on the Innamincka Dome in the Cooper Basin. Drilling of the initial wells is complete

and testing has begun. Bengal has a 25% interest in two of the initial test holes to be drilled. The Company’s net

estimated cost for these two test holes is $350,000. The resource potential of the coal seam gas and determination of

plans for any subsequent pilot program will be determined on the basis of the test hole results, which are anticipated to

be complete in the first quarter of calendar 2010.

Bengal holds a 10% interest in the offshore Timor Sea Permit AC/P 24, which the Company earned through the drilling

of the Katandra-1 oil discovery well in December 2004. The joint-venture partners had earlier decided that an additional

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processing stage would be required on the 3D seismic shot over Katandra prior to making a decision regarding the

proposal of follow-up appraisal drilling. The partners have since received approval from the Northern Territory

Government for extension of the license to June 2011, subject to a more technically elaborate merging and

reprocessing of two existing 3D seismic surveys in this year’s work program ended June 2010. An exploration well will

be required to retain the block past June 2010 in the final year of the permit. The operator’s proposed work program is

estimated to have a net cost to Bengal of US$112,700 ending in the first quarter of calendar 2010. Any follow-up

appraisal drilling would occur the following year and would be contingent on the outcome of the pre-stack depth

migration processing, which is designed to create a picture of complex underground layers.

SUMMARY

Bengal’s strategy going forward will be to continue to pursue large land positions with operational control, minimal

upfront capital requirements, high working interests and strong prospectivity. The Company also continues to review

strategic mergers and acquisitions to enhance its portfolio of projects and prospects. Bengal believes its base of

production combined with its balanced portfolio of exploitation and exploration opportunities in India and Australia

position the Company for long-term growth.

SELECTED QUARTERLY INFORMATION

(000s, except per share amounts) Quarter Ended

12/31/09 09/30/09 6/30/09 3/31/09 12/31/08 9/30/08 6/30/08 3/31/08

Petroleum and natural gas sales $ 413 $ 505 $ 574 $ 667 $ 825 $ 1,482 $ 1,952 $ 1,259Cash flow from (used-in)operations (264) (263) (630) (85) 303 1,094 625 (527)

Per shareBasic and diluted (0.01) (0.01) (0.03) (0.00) 0.02 0.06 0.03 (0.03)

Funds from (used in)operations (347) (295) (298) (92) (29) 367 860 (226)

Per shareBasic and diluted (0.02) (0.02) (0.02) (0.01) (0.00) 0.02 0.05 (0.01)

Net loss $ (885) $(1,848) $ (865) $ (839) $(6,916) $ (812) $ (351) $ (632)Per shareBasic and diluted (0.05) (0.10) (0.05) (0.05) (0.34) (0.04) (0.02) (0.03)

Additions to capital assets,net $1,120 $ (426) $ 154 $ 254 $ 1,096 $ 3,842 $ 1,532 $ 575

Working capital 2,501 3,970 1,764 2,189 2,642 3,783 7,224 8,043

Total assets 8,928 9,159 11,839 12,664 13,459 22,812 21,134 20,410

Shares outstandingBasic and diluted 18,213 18,213 18,213 18,213 18,213 18,213 18,213 18,198

OperationsAverage daily production

Natural gas (Mcf/d) 422 787 684 712 842 609 734 542Oil and NGLs (bbls/d) 30 53 58 63 65 84 96 93Combined (boe/d) 100 184 172 182 205 186 218 184

Netback ($/boe) $ 21.39 $ 11.77 $16.78 $14.86 $25.90 $ 49.75 $59.37 $ 52.25

Petroleum and natural gas revenues peaked in the three months ended June 30, 2008 due to historically high

commodity prices. Production levels were also high due to the recent acquisition of the Oak B.C. gas wells on February

13, 2008 combined with existing Kaybob gas and Toparoa oil production. Gas production volumes continued upward in

the quarter ended December 31, 2008 due to commencement of production from the new Oak 1-30 well. Since that

time, volumes and revenues have been on a declining trend due to natural reservoir declines and lower commodity

prices and the sale of the Kaybob gas wells in September, 2009.

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In the quarter ended December 31, 2008 the loss is increased by goodwill and ceiling test impairment charges and in

the quarter ended September 30, 2009 the net loss was increased by a loss on the disposal of oil and gas assets.

FINANCIAL INSTRUMENTS

Financial instruments comprise cash and short term deposits, accounts receivable and accounts payable and accrued

liabilities. The fair values of these financial instruments approximate their carrying amounts due to their short-term

maturities. Bengal has not identified any embedded derivatives in any of its contracts.

DISCLOSURE CONTROLS & PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING (ICFR)

Disclosure Controls and Procedures

The Company has established disclosure controls and procedures for the timely and accurate preparation of financial

and other reports. Disclosure controls and procedures are designed to provide reasonable assurance that material

information required to be disclosed is recorded, processed, summarized and reported within the periods specified by

applicable securities regulations and that information required to be disclosed is accumulated and communicated to the

appropriate members of management and properly reflected in the Company’s filings. Consistent with the concept of

reasonable assurance, the Company recognizes that the relative cost of maintaining these disclosure controls and

procedures should not exceed their expected benefits. As such, the Company’s disclosure controls and procedures can

only provide reasonable assurance, and not absolute assurance, that the objectives of such controls and procedures

are met. The Chief Executive Officer and Chief Financial Officer oversee this evaluation process and have concluded

that the design and operation of these disclosure controls and procedures are not effective in providing reasonable

assurance that material information required to be disclosed by the Company in reports filed with the Canadian

securities regulators is accurate and complete and filed within the periods required due to the material weaknesses

identified in internal controls over financial reporting as noted below. The Chief Executive Officer and Chief Financial

Officer have individually signed certifications to this effect.

Internal Controls over Financial Reporting (ICFR)

The Chief Executive Officer and Chief Financial Officer of Bengal are responsible for designing and ensuring the

operating effectiveness of internal controls over financial reporting or causing them to be designed and operating

effectively under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting

and the preparation of financial statements for external purposes in accordance with Canadian GAAP. Bengal’s

management has assessed the design and operating effectiveness of internal controls over financial reporting.

There were no changes in the Company’s ICFR in the quarter ended December 31, 2009 that have materially affected,

or are reasonably likely to affect, the Company’s ICFR. While Bengal’s Chief Executive Officer and Chief Financial

Officer believe the Company’s internal controls and procedures provide a reasonable level of assurance that they are

reliable, an internal control system cannot prevent all errors and fraud. It is management’s belief that any control

system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the

objectives of the control system are met.

During the design and operating effectiveness assessment certain material weaknesses in internal controls over

financial reporting were identified, as follows:

Management is aware that there is a lack of segregation of duties due to the small number of employees

dealing with general and administrative and financial matters. However, management believes that at this time

the potential benefits of adding employees to clearly segregate duties do not justify the costs associated with

such increase;

Many of Bengal’s information systems are subject to general control deficiencies including a lack of effective

controls over spreadsheets, access and documentation. The Company expects that some deficiencies will

continue into the future; and

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Bengal does not have full-time in-house personnel to address all complex financial and non-routine tax issues

that may arise. It is not deemed as economically feasible at this time to have such personnel. Bengal relies on

external experts for review and advice on complicated financial issues and for tax planning, tax provision and

compilation of corporate tax returns.

These weaknesses in internal controls over financial reporting result in a more than remote likelihood that a material

misstatement would not be prevented or detected. Management and the Board of Directors work to mitigate the risk of

material misstatement; however, management and the Board do not have reasonable assurance that this risk can be

reduced to a remote likelihood of a material misstatement.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by Bengal are disclosed in Note 1 to the audited Consolidated Financial

Statements for the years ended March 31, 2009 and 2008. Certain accounting policies require that management make

appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of

assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of

new information and changed circumstance may result in actual results or changes to estimated amounts that differ

materially from current estimates. A detailed discussion of the critical accounting policies and practices of the Company

which helps to assess the likelihood of materially different results being reported is disclosed in the March 31, 2009

Annual Management Discussion and Analysis.

FINANCIAL REPORTING UPDATE

Recent pronouncements

The CICA Accounting Standards Board (AcSB) confirmed the changeover to IFRS from Canadian GAAP will be

required for publicly accountable enterprises for interim and annual financial statements effective for fiscal years

beginning on or after January 1, 2011, including comparatives for 2010. The Company continues to perform analysis on

the major areas impacted by IFRS and will also continue to monitor standards development as issued by the IASB and

the AcSB as well as regulatory developments as issued by the Canadian Securities Administrators, which may affect

the timing, nature or disclosure of its adoption of IFRS.

One of the major changes from Canadian GAAP to IFRS will be the transition from Full Cost Accounting, which Bengal

uses, to accounting for oil and gas assets under IFRS. In July 2009 an amendment to IFRS 1 First Time Adoption of

IFRS was issued that allows an entity that used Full Cost Accounting under its previous GAAP to elect to measure oil

and gas assets using the net book value of the assets under GAAP, after testing for impairment. Exploration and

evaluation assets net book value should be readily identifiable as these assets would generally have been excluded

from the full cost pool. The balance of the development or production assets is then allocated using reserve volumes or

reserve values. Bengal expects that it will use this exemption.

Future Accounting Changes

In May 2009, the CICA amended Section 3862, “Financial Instruments – Disclosures,” to include additional disclosure

requirements about fair value measurement for financial instruments and liquidity risk disclosures. These amendments

require a three level hierarchy that reflects the significance of the inputs used in making fair value measurements. Fair

value of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for

identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices

for which all significant outputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that

are unobservable and significant to the overall fair value measurement. These amendments are effective for Bengal on

March 31, 2010.

RISK FACTORS

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There are a number of risk factors facing companies that participate in the international oil and gas industry. A summary

of certain risk factors relating to our business is provided in the Risk Factors section of our Annual Information Form on

SEDAR at www.sedar.com.

ADDITIONAL INFORMATION

Additional information relating to Bengal is filed on SEDAR and can be viewed at www.sedar.com. Information can also

be obtained by contacting the Company at: Bengal Energy Ltd., Suite 1140, 715 - 5 Avenue S.W., Calgary, Alberta T2P

2X6 or by e-mail at info@bengalenergy.ca or by accessing Bengal’s website at www.bengalenergy.ca.

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CORPORATE INFORMATION

AUDITORS KPMG LLP • Calgary, Canada

LEGAL COUNSEL Burnet, Duckworth & Palmer LLP • Calgary, Canada Allens Arthur Robinson • Brisbane, Australia

BANKERS Royal Bank of Canada • Calgary, Canada West Pac Bank • Brisbane, Australia Commonwealth Bank • Brisbane, Australia

REGISTRAR AND TRANSFER AGENT Valiant Trust Corporation • Calgary, Canada

INVESTOR RELATIONS Bryan Mills Iradesso • Calgary, Canada

DIRECTORS Chayan ChakrabartyRichard N. Edgar Edwin (Ted) S. Hanbury James B. Howe Bradley G. Johnson Judith A. Stripling Ian J. Towers

GOVERNANCE AND DISCLOSURE COMMITTEE All Directors are members of the Committee

AUDIT COMMITTEE James B. Howe Judith A. Stripling Ian J. Towers

RESERVES COMMITTEE Richard N. Edgar Edwin (Ted) S. Hanbury Ian J. Towers

COMPENSATION COMMITTEE Richard N. EdgarEdwin (Ted) S. HanburyJudith A. Stripling Ian J. Towers

OFFICERS Bradley G. Johnson, Chief Executive Officer Chayan Chakrabarty, President James Mott, Vice President, Exploration Bryan C. Goudie, Chief Financial Officer Bruce Allford, Secretary

STOCK EXCHANGE LISTING TSX: BNG